Good afternoon, Ladies and Gentlemen. And thank you for standing by. Welcome to the Murphy Oil Corporation first quarter 2010 earnings conference call. At this time, all participants are in a listen-only mode. (Operator Instructions) I'd like to remind everyone that this conference call is being recorded today, Thursday, May 6, 2010, at 12 p.m. Central Time. I'll now turn the conference over to Mr. David Wood, President and Chief Executive Officer. Please go ahead, sir.

Thank you, Operator. Good afternoon and thank you for joining us on our call today. With me are Kevin Fitzgerald, Senior Vice President and Chief Financial Officer, John Eckart, Vice President and Controller, Mindy West, Vice President and Treasurer, and Craig Bonsall, Supervisor of Investor Relations I'll now turn the call over to Craig.

Thanks, David. Welcome everyone and thank you for joining us. Today's call will follow our usual format. Kevin will begin by providing a review of first quarter 2010 results. David will then follow with an operational update after which questions will be taken. Please keep in mind that some of our comments made during this call will be considered forward-looking statements, as defined in the Private Securities Litigation Reform Act of 1995. As such no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors see Murphy's 2009 Annual Report on Form 10-K filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I'll now turn the call over to Kevin for his comments.

Thanks, Craig and welcome everyone. Net income in the first quarter of 2010 was $148.9 million or $0.77 per diluted share and this compares to net income in the first quarter of '09 of $171.1 million or $0.89 per diluted share. The 2010 quarter included $41.3 million or $0.21 per diluted share of after-tax losses on transactions denominated in foreign currencies compared to after-tax gains of $26.1 million or $0.14 per share on those transactions in the 2009 quarter. The 2009 quarter also included income from discontinued operations of almost $100 million or $0.52 per share, as we sold our operations in Ecuador. This income included an after-tax gain of $104 million on that sale. Compared to the 2009 first quarter, the 2010 quarter was favorably impacted by significantly higher worldwide cruel oil prices. In the downstream part of the business, earnings in the 2010 quarter were negatively affected by significantly lower refining margins and planned shut downs for turnaround in our Monroe, Louisiana and Milford Haven, Wales refineries. Looking at income by segment, in E&P segment from continuing operations net income in the first quarter 2010 was $247 million compared to income from continuing operations in the first quarter of last year of $50.3 million. Higher E&P earnings for 2010 were mostly attributable to the previously mentioned higher crude oil prices, which were up about 50%, but higher natural gas sales prices and volumes along with lower exploration expenses also contributed. Crude oil, condensate and gas liquids production for the current quarter averaged approximately 139,100 barrels per day in 2010 slightly lower than the 2009 quarter. Excluding 2009 production from discontinued operations in Ecuador, quarterly production in 2010 increased 4% over last year. The increase from continuing operations was mostly attributable to production from Thunder Hawk in the Gulf…

Thanks, Kevin. Externally, the first quarter of 2010 was a continuation of trends established in the second half of 2009, while crude oil prices remain buoyant around $80, a barrel domestic natural gas prices were at $5 per Mcf. Our portfolio heavily weighted towards oil fared reasonably well. Production for the first quarter averaged over 196,000 barrels of oil equivalent per day of which 70% was oil. Projects we brought on last year continued to progress. We have reached Phase I [path] at SK Gas are still ramping up at Azurite and will later this year bring on another well at Thunder Hawk. Overall, production for the quarter is above projection despite mechanical challenges at Azurite and equipment issues at SK Gas both now behind us. Tupper main in British Columbia, Canada continues to impress with rates over 90 million cubic feet a day, as we have improved plant capacity there. Tupper West is on track for our Q2 2011 start up from 180 million cubic feet a day new build plan. At Kikeh, production is good around 116,000-barrels of oil a day with associated gas of late near 120 million cubic feet of gas per day. Our exploration program this year will be a step up in activity from last years and is off to a good start with successful wells just an ounce at DC4 in the Gulf and Dolfin in Malaysia. At DC4, the well was drilled to a total depth of 13,195 feet and encountered 156 feet of good quality oil pay in three zones. Going in, we ranked this as most likely a gas prospect given proximity to Dalmatian, which we discovered in 2008 but have been very pleasantly surprised. We are re-looking at development options but still favor here Dalmatian as a subsea natural…

Your first question comes from Evan Calio with Morgan Stanley. Please go ahead

Hi, good afternoon, gentlemen, this is Ryan Todd actually of Morgan Stanley. A few questions starting out on the Eagle Ford. Can you clarify, have you drilled five wells and completed three up to this point? I know, we've seen the results of two. Is there any comment on the third and have you learned anything with the wells that you've seen that would change your past comments that we've seen in terms of costs and reserves per well?

Yes, Ryan, we have drilled three and reported results, drilled five and reported results three and I mentioned all three in my comments. The latest well is an oil well and the other two were gas wells. The first well we drilled, what we've learned there is not all of the frac zones were open so it's an issue with that particular well bore, the IP on that well was over 11 million and so I think we can go back in and do remedial work there. Similarly, a new well that we actually acquired when we picked up a piece of acreage, which was drilled in and out of zone. It's just flowing at just over 2 million a day that I mentioned and then so we take a look at that, and then the third well which is the oil well in the Carnes is a great well and today, I was looking this morning before I came in and it's flowing 860-barrels of oil and 770,000 cubic feet. So that's after almost 60 days, 58 days today of production, so a real strong well, and so we're continuing on with our program to appraise our acreage across the three different parts, the oil part, the oil and gas part and the gas part and we'll start to focus in. We should be spudding here pretty soon another well within the next day or so up in the same oil area and that in Carnes County, and so clearly it's got a lot of potential right now.

Great, thanks and if I could switch over to Azurite, I know that the second well at Azurite has some issues. Can you discuss a little bit what you've seen out of the second well, the timing on the third well start up and have the operations there changed at all what you view will be the production capacity of the field or your year end exit rate?

You know, Ryan, the capability of the wells to flow I think is still the same, it's still good. What we've suffered here is some mechanical below the mud line issues and particularly with the second well and that has been fixed and the third well is now just starting up. So, I think, we've got the mechanical issues behind us and I expect that to do better as we move on.

And what's the current production rate at Azurite?

Ryan, this is Mindy. We're expecting production at Azurite for the second quarter to be a little over 7100-barrels a day.

Your next question comes from Arjun Murti with Goldman Sachs. Please go ahead.

Thank you, David. I think you mentioned you'll be adding some rigs to the Eagle Ford this year. How many, I guess, exploration wells if you will do you think you'll need to drill before you can move towards development mode?

We set out with the idea of drilling six spread about the play and so we're kind of getting to that number and the way that it works in that play is we participate in getting data from other operators as well. So, it's not like you only have your own wells. I think, six is probably about right. In the oil area where we've had this very good well and we're drilling the second well, if this second welcomes in anything like the first well, then I think, we'll be pretty comfortable in looking at some kind of localized development of that acreage, and our full process is in order to drive down costs and to drive up results of the wells, we need to kind of sanction the particular area. So, later this year assuming this next well meets expectation, we would go through kind of a formal sanction process and then set off with the development of that and that would be yield.

Got it. I think, I've got it. So, it's probably a innovative process where you kind of gain comfort in an area sanctioned, I think you used the word localized development while you're probably still drilling exploration wells that will where and at some point other areas will move forward as well presumably?

Arjun, you got it exactly.

Thank you. And then, I appreciate the additional disclosure on the refining versus marketing businesses that's much appreciated. Do you view refining as critical to having because you have such a large marketing business? Maybe that will be the question.

You know, it's not necessary. I think when we started down the path of this Murphy USA having a refinery capability, I think had value, but today, we sell four times more fuel than we actually make and I think that connection is really not the same today. The way that I look at the refinery business and we're releasing results of the different business units so that everybody can see kind of what I get to see as the performance goes, having refineries really doesn't stop us from doing anything else. All I've asked our refiners to do and we organize that business a bit is to deliver what those plants are capable of delivering and I'm very gratified to see that Monroe is starting to do that and Milford Haven clearly I'm expecting that so I just look at those as individual businesses.

Your next question comes from Mark Gilman with Benchmark Company. Please go ahead.

David, good afternoon. Regarding the De Soto Canyon well, if I recall correctly your pre-drill prospect size on that well was also pretty modest. Is that also in validated by the surprise in terms of encountering oil pay?

You know, when you look at the amplitude and the calibrations that we have, this looked very similar to Dalmatian. What was different here in this well is we found three pay sands and about a third more net pay than was thought, which is always a nice thing to happen including the main sand here that's a nice very clean sand over 100 feet of net cut. And we think that was masked somewhat seismically by the presence of the pay sand above it. So that happens and so I accept that. Oil versus gas is a little bit of a conundrum here because in this big home section and that's the geologic level we're dealing with, quite often it is oil and quite often it is gas. Our risking here going in was that there was only a slight chance of finding oil. As it turned out all three sands are oil. Geophysically attribute wise there's no difference here at all. In terms of size we had this as a 50-70 Bcf prospect. I think today, we're at 20 to above 20 million barrels oil here and a part of that is because there's more net pay than we originally planned but also I think we've got a little bit better sense of what we're dealing with here. We're going to go back and recalibrate this of course. We have a number of other amplitude anomalies here to see what else we can do, so good news, nice to find more pay than prognosed and I have to say finding oil which I regard as being a little higher than gas here some bad news are.

David, could I ask you to try to clarify the situation regarding Blocks L&M and the boundary and border dispute? It appears as if you relinquished the contract or the contract was nullified, but then there's also a suggestion that there's negotiation going on for additional and/or the rein statement of your participation. Can you comment?

You know, Mark, we've released what we're wanting to release on that. Its Blocks L&M are no more that is the agreement or agreements being worked between the two governments and that's really all I can say at this time.

Okay. Let me try one more if I could. A gas commerciality threshold, if you can assess one for what you have in Block H and where you stand vis-a-vis that level?

Yes Block H is on interesting block. We've drilled a number of wells there and to be honest not had the level of success that we would hope but I think what we're realizing is that it's largely gas, this well found oil as we had hoped but the reservoir quality was not good enough. We've got probably a couple of Tcf, maybe a bit more than that with this new discovery. I think there's two ways to go here, or actually three ways to go. You can tie into some existing infrastructure, you can develop your own infrastructure, or you can do something floating. I think tying into existing infrastructure or developing new infrastructure is probably the way to go but we're not enough volumes proved up yet to do a standalone. We're working closely with our partner Carigali and looking what our options are. We have a pretty extensive list of prospects remaining on the block. I don't know that any of them are as big as the biggest ones that we found, but there's a lot of them and so I think there's a large resource here, I think, as we continue to appreciate what was there and what commercial issues are, I think ultimately this will be developed and that's my sense. It won't be quick but I think geologically it's a pretty attractive place.

Your next question comes from Paul Sankey with Deutsche Bank. Please go ahead.

Hi, David. See you next week. About a year ago, maybe more, you kind of quite openly talking about acquisitions as kind of a replacement for Kikeh ultimately, I guess, and also actually at the time, I hope that commodity prices would stay low to give you more opportunities. To me it feels as if now with the exploration you've had just this quarter that the organic opportunities that is looking plenty strong enough to drive these past Kikeh. Is that how you're seeing things?

You know, given the type of company that we are and the balance sheet, to be honest, I would have liked this to be in a lot longer load time to give us an advantage to go and buy some things. I was particularly targeting North American natural gas a couple years ago when we talked and I think we've done that through lease acquisitions both at Montney and at the Eagle Ford and the target that we had set, which we've been talking about here recently is to get to about 10 Tcf, because I think that is kind of meaningful for our company and we'll probably with what we've got two thirds of the way there. So, we didn't have to buy anything to get there and we've got ways to get the remaining distance up to the 10-T either by adding a new play looking at that pretty hard all while continuing to grow in the two we've got. So, I feel that that itch and that gap in our portfolio has been scratched. If you look at our exploration program in the last, or last year and this year so far, we've drilled 10 wells and made six discoveries that are likely to be developed, which is a pretty good rate and higher than I would hope for, but I'm happy to have it. The thing that's missing in that is this needle moving discovery and I think that's the issue that we have looking forward but the nice thing looking forward is that this year towards the end of the year and it just happens to be that way, we put a number of needle moving prospects. So, if we can have any sort of success rate, then I'll feel real good about our exploration program both this year and then years going forward. So that kind of negates some of the need to go but acquire things having said that if something looks right we kind of take a hard look at it but don't have to do that.

Well, there's nothing like putting a bit of pressure on your exploration program?

No, good play is like to do that and we've got good folks so I'm really not that worried about it.

I understand. Just very specifically, Monroe, I guess, is potentially subject to an interruption from oil supply given its position. Can you add anything on that current situation in the Gulf of Mexico? And I'll leave it there, thanks.

I'm not sure if you say oil supply is that by halting tanker. Okay, we've looked at that and we don't see any, use right now, but of course that's something that we take a hard look at.

But it would be, you have alternative supply anyway, I guess, it doesn't have to come by tanker?

Yeah. We've got some options.

Right, thanks a lot.

Your next question comes from Paul Cheng with Barclays Capital. Please go ahead.

Hi guys. First wanted to say thank you for breaking out US marketing and refining resell. We really appreciate.

Good, Paul, we're happy to do it.

Dave, in the Eagle Ford, I think you've been talking about bringing it to three rigs. Given it's a pretty decent success on the second well, is there anything for this year going to go beyond three rigs and also what is your budget for CapEx in the Eagle Ford this year?

Yeah, Paul, on the first part of your question, the third well will just help us appraise the acreage position we've got. If we go ahead and have the success that we hope with the second well in Carnes County, as I mentioned on earlier call we would look to sanction that as a development and then of course that would require more than the rigs that we've got, and so I don't want to get ahead of ourselves here but clearly, there will be a step up in activity if that's the case that happens.

So, you don't want to say that in the development mode whether you're going to employ say a five rig, six rig, so it's just little bit premature at this point?

It's just a little premature and so if you asked me the question it a month or so, I could better address it, and this year, actually your second question, Paul, we've got $115 million in our budget for Eagle Ford spend.

And that's for three rigs program or two rigs?

That's two rigs basically. Originally, when we wrote the budget we had two rigs but the second rig not starting until the middle of the year and we brought that forward and it actually started up at the end of the first quarter. So, an extra rig for half a year would be incremental to that number.

And Dave, I have to apologize if I miss that. Did you mention what is the current production rate from the first well?

Yeah, the first well is making, you mean, the first well that we did, the gas well?

Yeah.

It's making about just under a million cubic feet a day, so it climbed very rapidly from its IP and we've done some investigation within the well bore and not all of the frac zones are open to flow, actually very few of them are.

Are they currently stabilized at the 1 million cubic feet per day rate?

Well the trouble is there's not many of the zones open and it looks like its pretty steady at that rate.

How about in the second, you're saying right now it's about 800 barrels per day. Are they still declining at a pretty rapid pace or start to stabilizing somewhat?

The oil well, which is the ones in Carnek County started at just over 1400 barrels a day, production when I looked before I came in here for the call it was 860 barrels a day and 0.7 million cubic feet and if you're looking at the plot, it's pretty much a straight line, so it's a very, very strong well. We've been producing as of yesterday 58 days and by the way, we're flowing through casing. We haven't put tubing in that well yet.

But I guess, my question is that in the current late 860, in the last April days are we starting to see some stabilization or still in a pretty rapid decline at this point?

It's still in a decline but it's not what I call a rapid decline.

Okay. And did you talk about the Monroe that you don't see any disruption? I presume you haven't seen any disruption for your Mexico production due to the BP oil spill also?

Paul, that's correct. Let me just go back to the Eagle Ford. We think that well is going to recover, if you use the current decline, something in excess of 500,000 barrels that gets you there.

That's a very good well.

No, we've not seen anything in the Gulf that's impacted our production.

Two more questions if I could. One, Dave, do you have a target except 2010 oil and gas production rate? Secondly, we don't have to go through here maybe either Craig or Mindy or Kevin can give me a call, when I look at your report of sales warning, not the production report of sales warning and the price realization that you put down in your Press Release, when I did the math, the report that's calculated from there and your reported revenue in US, Canada and Congo are quite different so maybe someone can help me to reconcile that?

Yeah, Paul. I think we can get you the numbers that get you comfortable there and we'll just have Craig give you a call.

Paul, in answer to your question about production or estimate, this is a fourth quarter average but we're estimating around 217,000 barrels a day of oil equivalent net to Murphy for the quarter. And then, as revenue numbers that you're talking about, in the US, it was some gas gathering income that we consider other income that's affecting those revenue numbers and in Canada we had some royalty adjustments that I believe it was Terre Nova at Seals that also affected those numbers, Hibernia, excuse me, and Seals that affected those numbers.

Mindy, are those one off or is that just going to continue to have a similar effect in the future?

No, that was just an adjustment that we made during the quarter?

No, I think that for Canada that the royalty adjustment is one off, how about US the gas gathering?

It was a one-time type catch up adjustment.

Okay. So both of them is one time?

Correct, although in the US, we do sometimes have Murphy gas gathering other income.

How about in the Congo?

In the Congo, that is a gross up for the way that taxes are paid over there. We gross up the revenue number but if you notice then the functional results of operations paid that we provided along with the news release, the tax rate if you calculated it was extremely high and that's why.

I see, very good, thank you.

Your next question comes from Blake Fernandez with Howard Weil. Please go ahead.

Hi, good afternoon, guys. Thanks for taking my question. My first question was on the foreign realizations in particular in Malaysia. It seemed like there was a distinct drop off sequentially, yet the environment at least looking at Tapis quarter-over-quarter seemed to actually increase over $1 a barrel. And so, I'm trying to see if you could help me kind of connect the dots on what's going on there and how we should look at this going forward?

What happened in the quarter actually reflected the weakness in Tapis versus WTI first quarter compared to fourth quarter. Fourth quarter, especially November/December, Tapis was well above TI, but during the quarter it traded at a discount of $6, $6.50 for the entire quarter. And so, our realization in Malaysia is reflected of that weakness.

Okay, Mindy, so we should not necessarily be looking at it on an absolute basis but more or less relative to WTI then, right?

It's volatile, the differential versus WTI is fairly volatile, but our crude and Kikeh is priced off of the Tapis differential. So, it does bounce around and quarter-to-quarter there was a difference.

Okay. I know you've given the second quarter guidance. I'm just curious, David, do you have any sense for the timing or the mechanical issue and the Kikeh intervention work, is that all supposed to be corrected heading into the third quarter do you think?

Yes, I think so. I don't see that being prolonged.

Okay. And then, the last one I had for you was on the retail segment. I guess, I was expecting maybe some upside surprise there just given some of the numbers we've seen from peers. Were you at all negatively impacted from a volumetric standpoint due to the weather, I believe it was maybe January or February along the East Coast, did that have any impact making its way down to your operations?

No, weather it can be a factor. Blake, I think, the big issue here is you've got to remember that we don't sell much diesel at all and if you look at others their mix of gasoline and diesel is different. And so, I think that's one of the things that might help calibrate that.

Your next question comes from Gene Gillespie from Gillespie Consulting Group. Please go ahead.

Okay, David? I've got a couple of things here. Can you give us the moving pieces on the dry hole expense guidance for the quarter?

I'll do that for you, Gene this is Mindy. We're expecting dry-hole costs of $8 million to $38 million to $8 million, as a result of the Batai dry-hole carryover cost. And the rest of the wells that are included in second quarter guidance would be the Deep Blue well that's almost $20 million net to Murphy, and then a couple of prospects that we're going to be drilling in Shallow Water Block SK 311 in Malaysia, that's roughly $11 million.

Is there any change in your Gulf of Mexico exploration plan due to recent events?

Gene, I think it's too early to say there. Our rig once it's finished with this DC4 well goes for a couple of month for now and so we won't be doing anything for a couple months. And then, when the rig comes back, we have the program lined up in front of us. I think the big question for us will be do we want to go back to this DC4 area or do we want to go do something else, so we'll look at that now.

So, if you choose not to go back to DC4, are you going to take it to Green Canyon?

That was the original plan, yes.

Okay, does your partner in Samurai have plans to drill an appraisal well this year?

We're talking with both our partners about Samurai. From my perspective, I'd like to get on and appraise it and make a development call here. I think it's a very nice discovery. We just don't know what the size is, and so I'm anxious to do it sooner rather than later.

And I couldn't help but notice the common resources $9,700 an acre in the Eagle Ford. That's a pretty attractive number.

Yes, it is. I think it helps validate a lot of that play. We've got a couple hundred thousand net acres, as we've said and we've got some in the oil window too. So, I'm pretty happy with where we're at.

Have you disclosed what your average cost is per acre?

We have not but because we got in early, Gene, it's not high. It's not too far off $1,000 an acre, I think is the number, but I'm doing that from memory.

How much an acre, I'm sorry?

About $1,000.

$1,000. So, about a year ago you were paying like $300 an acre for?

Yes, something or less.

Pretty good. Nice play.

Your next question comes from Pavel Molchanov with Raymond James. Please go ahead.

Question on your marketing business, any opportunities in the retail arena in terms of rolling up additional stores and also if you can comment on the internal traffic growth that you guys are seeing at the pump?

We have plans this year, plans on to add 80 stations in the same area that we operate now, and we're managing the growth on that program. I think we could grow faster than that but I think we're trying to do it as smart as we can. We also see that there's a number of acquisition opportunities some of them for small numbers of stores and some of them for larger numbers and those are things we look at. We've not pulled the trigger on any of those at all. So, I think the space is going to be right for consolidation. We think that we've got an advantage business model there, low cost, high volume, and so we take a keen look at that, it's something that we're looking to grow. And I think 80 stores this year is a good number for this year. We have grown 120 in years past.

Your next question comes from Kate Lucas with Collins Stewart. Please go ahead.

I've just got a couple of quick questions. The first one, and I apologize if you gave the answer, I missed it. Did you give the cost of the Drees well?

Yes, the Drees, I think, we gave the cost of the Drees well but from memory, I want to say about $11 million.

Okay and was it Drees that was the 500,000-barrels to be recovered in your comments, David?

Yes, yes, that's the well that is a very nice oil well.

Great. And then, more of a strategic question, you talked a little bit about acquisitions but just in terms of divestitures it looks as though a lot of your peers have gotten some pretty favorability pricing for some other assets. When you think about your portfolio, is there anything, would you be amendable to divesting of maybe anything you thought were either non-core or not realizing its full valuation potential within the portfolio?

Yes. Kate that's one of those things you kind of always look at. If you look over the last few years the most recent thing we sold was Ecuador. My view of Ecuador was below ground attractive, above ground and the valuation was pretty slim. So, it was one of those things that we worked at for awhile and I think made an appropriate move. There's always things that you look at in your program and you say, is that the right timing to do something and so we do that. But there's nothing pregnant in front of us that would say hey there's something that I want to get rid of, but we look at it all the time.

(Operator Instructions) Your next question comes from Mark Gilman with Benchmark Company. Please go ahead.

Hi, David what's your thought on how long Kikeh holds plateau?

We actually don't split Kikeh out. We kind of Block K, the way we look at it because it's all one PSC, Mark. And I was actually just looking at some of that stuff last week, and so if you have Kikeh and then you have Kakap and then you have Siakap North, you can have a net to us plateau that runs 2014 plus type number.

Your next question comes from Ray Deacon with Pritchard Capital. Please go ahead.

Yes, hi, David. I was wondering, if you could talk about what scenario would allow you to go to a higher level of activity in the Eagle Ford I guess? How many results would you need to see?

I kind of underscore my earlier comments, if we can get the second well in the oil area in Karnes to allow us to get comfortable, we have a development there, then, I'm sure our guys would come forward and sanction that particular area. So, I mean, that's a 30 to 40-day, 50-day type of timeline. Other parts of the play, we're still evaluating. I talked about a couple of well results that started off and one of them is not as good. We think we understand what that issue is. We got to get our head around that. We've got a couple of wells that we're in the process of fracing now, we need to see those results. So, this year, as we set it out was one where we were going to evaluate different pockets of our acreage and we're doing that. The early success in Karnes allows us to immediately focus on that. I'm hopeful that we'll have one or two of these other areas have some attraction and then we'd be able to focus in on those. That's kind of a thought process. And then, I think, two wells and adding the two rigs and adding a third rig will get us a level of activity that will process that data gathering along.

Your next question comes from Gene Gillespie from Gillespie Consulting Group. Please go ahead.

As a follow-up to Kate's question, a recent transaction would suggest that your 5% interest in Syncrude might be worth a couple billion dollars. That sounds like a pretty attractive price and given the on-again off-again issues of oil mining, what are your thoughts?

I think on the asset itself, Gene, Syncrude is a good asset and it's got a wonderful long life production profile with some resource upside. And so, I actually like the asset, I can actually see why people are paying the prices they are. And I think there is a place for it today in our overall production program. So, unless somebody comes and writes me a big check here, I'm happy to have it.

Your next question comes from Mark Gilman with Benchmark Company. Please go ahead.

David, give me a rough idea how you would split your 200,000 Eagle Ford acres between the oil prone and gas prone areas?

About half and half, Mark. I think if you look up at Karnes County, we're in the close to 40,000-acre number. And in that oil play, everybody defines oil trends and gas trends differently, so but as we would define it, we probably got 100,000-acres in the oil play, which stretches down Southwest of Karnes. We don't have anything Northeast of Karnes. And then, about 100,000 in the gas play. So, I'd split it that way.

Mr. Wood, there are no further questions at this time. Please continue.

Operator, thanks a lot. I appreciate everybody taking the trouble in calling in today. Thanks and we'll talk to you next time, we have one of these calls. Appreciate it.